It is well known that a significant percentage of oil remains in a subterranean formation after the costs of primary production rise to such an extent that further oil recovery is cost ineffective. Typically, only one-fifth to one-third of the original oil in place is recovered during primary production. At this point, a number of enhanced oil recovery (EOR) procedures can be used to further recover the oil in a cost-effective manner. These procedures are based on re-pressuring or maintaining oil pressure and/or mobility.
For example, waterflooding of a reservoir is a typical method used in the industry to increase the amount of oil recovered from a subterranean formation. Waterflooding involves simply injecting water into a reservoir, typically through an injection well. The water serves to displace the oil in the reservoir to a production well. However, when waterflooding is applied to displace viscous heavy oil from a formation, the process is inefficient because the oil mobility is much less than the water mobility. The water quickly channels through the formation to the producing well, bypassing most of the oil and leaving it unrecovered. For example, in Saskatchewan, Canada, primary production crude has been reported to be only about 2 to 8% of the original oil in place, with waterflooding yielding only another 2 to 5% of that oil in place. Consequently, there is a need to either make the water more viscous, or use another drive fluid that will not channel through the oil. Because of the large volumes of drive fluid needed, it must be inexpensive and stable under formation flow conditions. Oil displacement is most efficient when the mobility of the drive fluid is significantly less than the mobility of the oil, so the greatest need is for a method of generating a low-mobility drive fluid in a cost-effective manner.
Oil recovery can also be affected by extreme variations in rock permeability, such as when high-permeability “thief zones” between injection wells and production wells allow most of the injected drive fluid to channel quickly to the production wells, leaving oil in other zones relatively unrecovered. A need exists for a low-cost fluid that can be injected into such thief zones (from either injection wells or production wells) to reduce fluid mobility, thus diverting pressure energy into displacing oil from adjacent lower-permeability zones.
In certain formations, oil recovery can be reduced by coning of either gas downward or water upward to the interval where oil is being produced. Therefore, a need exists for a low-cost injectant that can be used to establish a horizontal “pad” of low mobility fluid to serve as a vertical barrier between the oil producing zone and the zone where coning is originating. Such low mobility fluid would retard vertical coning of gas or water, thereby improving oil production.
For moderately viscous oils—i.e., those having viscosities of approximately 20–100 centipoise (cP)—water-soluble polymers such as polyacrylamides or xanthan gum have been used to increase the viscosity of the water injected to displace oil from the formation. For example, polyacrylamide was added to water used to waterflood a 24 cP oil in the Sleepy Hollow Field, Nebr. Polyacrylamide was also used to viscosify water used to flood a 40 cP oil in the Chateaurenard Field, France. With this process, the polymer is dissolved in the water, increasing its viscosity.
While water-soluble polymers can be used to achieve a favorable mobility waterflood for low to moderately viscous oils, usually they cannot economically be applied to achieving a favorable mobility displacement of more viscous oils—i.e., those having viscosities of approximately 100 cP or higher. These oils are so viscous that the amount of polymer needed to achieve a favorable mobility ratio would usually be uneconomic. Further, as known to those skilled in the art, polymer dissolved in water often is desorbed from the drive water onto surfaces of the formation rock, entrapping it and rendering it ineffective for viscosifying the water. This leads to loss of mobility control, poor oil recovery, and high polymer costs. For these reasons, use of polymer floods to recover oils having viscosities in excess of 100 cP is not usually technically or economically feasible. Also, performance of many polymers is adversely affected by levels of dissolved ions typically found in formations, placing limitations on their use and/or effectiveness.
Water and oil macroemulsions have been proposed as a method for producing viscous drive fluids that can maintain effective mobility control while displacing moderately viscous oils. For example, water-in-oil and oil-in-water macroemulsions have been evaluated as drive fluids to improve oil recovery of viscous oils. Such emulsions have been created by addition of sodium hydroxide to acidic crude oils from Canada and Venezuela. The emulsions were stabilized by soap films created by saponification of acidic hydrocarbon components in the crude oil by sodium hydroxide. These soap films reduced the oil/water interfacial tension, acting as surfactants to stabilize the water-in-oil emulsion. It is well known, therefore, that the stability of such emulsions substantially depends on the use of sodium hydroxide (i.e., caustic) for producing a soap film to reduce the oil/water interfacial tension.
Various studies on the use of caustic for producing such emulsions have demonstrated technical feasibility. However, the practical application of this process for recovering oil has been limited by the high cost of the caustic, likely adsorption of the soap films onto the formation rock leading to gradual breakdown of the emulsion, and the sensitivity of the emulsion viscosity to minor changes in water salinity and water content. For example, because most formations contain water with many dissolved solids, emulsions requiring fresh or distilled water often fail to achieve design potential because such low-salinity conditions are difficult to achieve and maintain within the actual formation. Ionic species can be dissolved from the rock and the injected fresh water can mix with higher-salinity resident water, causing breakdown of the low-tension stabilized emulsion.
Various methods have been used to selectively reduce the permeability of high-permeability “thief” zones in a process generally referred to as “profile modification.” Typical agents that have been injected into the reservoir to accomplish a reduction in permeability of contacted zones include polymer gels or cross-linked aldehydes. Polymer gels are formed by crosslinking polymers such as polyacrylamide, xanthan, vinyl polymers, or lignosulfonates. Such gels are injected into the formation where crosslinking reactions cause the gels to become relatively rigid, thus reducing permeability to flow through the treated zones.
In most applications of these processes, the region of the formation that is affected by the treatment is restricted to near the wellbore because of cost and the reaction time of the gelling agents. Once the treatments are in place, the gels are relatively immobile. This can be a disadvantage because the drive fluid (for instance, water in a waterflood) eventually finds a path around the immobile gel, reducing its effectiveness. Better performance should be expected if the profile modification agent could slowly move through the formation to plug off newly created thief zones, penetrating significant distances from injection or production wells.
McKay, in U.S. Pat. No. 5,350,014, discloses a method for producing heavy oil or bitumen from a formation undergoing thermal recovery. McKay describes a method for producing oil or bitumen in the form of oil-in-water emulsions by carefully maintaining the temperature profile of the swept zone above a minimum temperature, Tc. If the temperature of the oil-in-water emulsion is maintained above this minimum temperature, the emulsion will be capable of flowing through the porous subterranean formation for collection at the production well. McKay describes another embodiment of his invention, in which an oil-in-water emulsion is inserted into a formation and maintained at a temperature below the minimum temperature. This immobile emulsion is used to form a barrier for plugging water-depleted thief zones in formations being produced by thermal methods, including control of vertical coning of water. However, the method described by McKay requires careful control of temperature within the formation zone and, therefore, is useful only for thermal methods of recovery. Consequently, the method disclosed by McKay could not be used for non-thermal (referred to as “cold flow”) recovery of heavy oil.
A new process has recently been disclosed that uses novel solids-stabilized emulsions for enhanced oil recovery. The added solid particles help stabilize the oil and water interface to provide enhanced stability to the emulsion. U.S. Pat. No. 5,927,404 describes a method of using the novel solids-stabilized emulsion as a drive fluid to displace hydrocarbons for enhanced oil recovery. U.S. Pat. No. 5,855,243 claims a similar method of using a solids-stabilized emulsion, whose viscosity is reduced by the addition of a gas, as a drive fluid. U.S. Pat. No. 5,910,467 claims the novel solids-stabilized emulsion described in U.S. Pat. No. 5,855,243. Pending U.S. patent application Ser. No. 09/290,518 describes a method for using the novel solids-stabilized emulsion as a barrier for diverting the flow of fluids in the formation.
Preparing an emulsion with optimum properties is key to successfully using the emulsion for enhanced oil recovery. Two important properties for using an emulsion in EOR processes are an emulsion's stability and its rheology. The emulsion should be shelf-stable, that is, the emulsion should be able to remain a stable emulsion without water or oil breakout when left undisturbed. In addition, the emulsion should be stable under flow conditions through porous media, i.e. in a subterranean formation. The emulsion's Theological characteristics are also important. For instance, EOR methods for which this emulsion may be used include injecting the emulsion as a drive or barrier fluid into a subterranean formation. Accordingly, the emulsion should have an optimum viscosity for injection and to serve as either a drive or barrier fluid. In practicing EOR, and particularly with using the emulsion as a drive fluid, it is useful to match the rheology of the emulsion with the rheology of subterranean oil to be produced. Oil displacement using a drive fluid is typically more efficient when the drive fluid has a greater viscosity than that of the oil to be displaced.
Because water and oil are readily available at most production sites, water-in-oil emulsions are a good choice for making the emulsions for EOR. Some oils possess the chemical composition and physical properties necessary to make stable water-in-oil emulsions. Examples of such compositions are polar and asphaltene compounds. However, if the oil does not contain the right type and sufficient concentration of polar and asphaltene compounds, the oil may not form stable water-in-oil emulsions. The previously cited art related to solids-stabilized emulsions suggests that asphaltenes or polar hydrocarbons may be added to these oils to improve their ability to form stable emulsions. U.S. Pat. No. 5,855,243, column 7, lines 6–10; U.S. Pat. No. 5,927,404 column 6, lines 44–47; U.S. Pat. No. 5,910,467 column 7, lines 3–6. However, this addition is not always successful because incompatibility between some oil components and the added asphaltenes and polars can result in phase separation or rejection of the added compounds. These cases limit the scope of the inventions disclosed in the U.S. Patents cited above.
Accordingly, there is a need for a method to produce an emulsion that can be made economically and is capable of performing under a wide range of formation conditions, including salinity, temperature and permeability. The present invention satisfies this need.